PG&E Corp (PCG) FY 2023 MD&A

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. See “Ratemaking Mechanisms” in Item 1. Description of the Business regarding how the Utility’s revenues are determined.

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Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:

•The Uncertainties in Connection with Wildfires, Wildfire Mitigation, and Associated Cost Recovery. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the costs and effectiveness of the Utility’s wildfire mitigation initiatives; the extent of damages from wildfires that do occur; the financial impacts of wildfires; and PG&E Corporation’s and the Utility’s ability to mitigate those financial impacts with insurance, the Wildfire Fund, and regulatory recovery.

In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening. In particular, in 2023, the Utility introduced or expanded its use of several measures including downed conductor detection, partial voltage force outs, and transmission operational controls. The Utility is also focused on undergrounding more lines each year while using economies of scale to make undergrounding more cost efficient. These initiatives have significantly reduced the number of CPUC-reportable ignitions and the number of acres burned. The success of the Utility’s wildfire mitigation efforts depends on many factors, including whether the Utility can retain or contract for the workforce necessary to execute its wildfire mitigation actions.

PG&E Corporation and the Utility have incurred and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain. If additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on the costs of the Utility’s wildfire mitigation initiatives.

The Utility is subject to a number of legal and regulatory requirements related to its wildfire mitigation efforts, which require periodic inspections of electric assets and ongoing reporting related to this work. Although the Utility believes that it has complied substantially with these requirements, it continually reviews and has identified instances of noncompliance. The Utility intends to update the CPUC and the OEIS as its review progresses. The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for late inspections or other noncompliance related to wildfire mitigation efforts.

Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. Once an ignition has occurred, the Utility is unable to control the extent of damages, which is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.

The financial impact of past wildfires is significant. As of December 31, 2023, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.125 billion, $400 million, $1.6 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries. These liability amounts correspond to the lower end of the range of reasonably estimable probable losses, unless expressly noted otherwise, but do not include all categories of potential damages and losses.

PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage through the Wildfire Fund, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Recorded liabilities in connection with the 2019 Kincade fire and the 2021 Dixie fire have already exceeded potential amounts recoverable under applicable insurance policies. As of December 31, 2023, the Utility has recorded insurance receivables of $430 million for the 2019 Kincade fire, $374 million for the 2020 Zogg fire, $526 million for the 2021 Dixie fire, and $63 million for the 2022 Mosquito fire.

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If the eligible claims for liabilities arising from wildfires were to exceed $1.0 billion in any Wildfire Fund coverage year (“Coverage Year”), the Utility may be eligible to make a claim against the Wildfire Fund under AB 1054 for such excess amount. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from wildfires, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable and therefore not subject to reimbursement, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. As of December 31, 2023, the Utility has recorded a Wildfire Fund receivable of $600 million for the 2021 Dixie fire. See “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility will be permitted to recover its wildfire-related claims in excess of insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard. The revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC, and it is possible that the CPUC could interpret the standard or apply it to the relevant facts differently from how the Utility has interpreted and applied the standard, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as receivables. As of December 31, 2023, the Utility has recorded receivables for regulatory recovery of $561 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire. See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information.

•The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business. The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administrative and general expenses) and capital costs (e.g., depreciation and financing expenses). The CPUC also authorizes the Utility to collect revenues to recover costs that the Utility is allowed to pass through to customers, including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. Although the Utility generally seeks to recover its recorded costs on a timely basis, in recent years, the amount of the costs recorded in memorandum and balancing accounts has increased. Other proceedings that could impact the Utility’s business profile and financial results include actions by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions, and the Utility’s application to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the regulatory and political environments, and other factors. For more information, see “Jurisdictions may attempt to acquire the Utility’s assets through eminent domain, and third parties may attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system” in Item 1A. Risk Factors, Notes 3 and 15 of the Notes to the Consolidated Financial Statements in Item 8, and “Regulatory Matters” below.

•PG&E Corporation’s and the Utility’s Ability to Control Operating and Financing Costs. Under cost-of-service ratemaking, a utility’s earnings depend on its ability to manage costs within the amounts authorized for recovery in its ratemaking proceedings. The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility plans to achieve such savings by improving the planning and execution of its work through increased efficiencies, including waste elimination through the Lean operating system. PG&E Corporation and the Utility also work to minimize financing costs by identifying and executing on opportunities to efficiently finance the business, which depends on capital market conditions.

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors and see “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially.

Tax Matters

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $32.9 billion and a California net operating loss carryforward of approximately $32.6 billion as of December 31, 2023.

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Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. At various dates throughout 2022 and 2023, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2023, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 247,743,590 shares resulted in an aggregate tax benefit of $1.2 billion recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. Cumulatively through December 31, 2023, the Fire Victim Trust sold all of its 477,743,590 shares resulting in an aggregate tax benefit of approximately $2 billion recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

Update on Ownership Restrictions in PG&E Corporation’s Amended Articles

Shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. For example, although PG&E Corporation had 2,611,366,666 shares outstanding as of February 14, 2024, only 2,133,623,076 shares (the number of outstanding shares of common stock less the number of shares held directly by the Utility) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles was 3.88% of the outstanding shares. As of February 14, 2024, the Fire Victim Trust reported having sold all of the shares of PG&E Corporation common stock it had owned and no longer owning any shares.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2023 and 2022.  See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

See “Results of Operations” in Item 7 of the 2022 Form 10-K for discussion of results of operations for 2022 compared to 2021.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) available for common shareholders:

PG&E Corporation’s net loss primarily consists of income taxes and interest expense on long-term debt. The decrease in PG&E Corporation’s net loss is primarily due to losses recorded in connection with the Wildfire-Related Securities Claims in 2022, with no comparable charges in 2023.

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Utility

The table below shows the Utility’s Consolidated Statements of Income for 2023 and 2022.  In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs do not impact net income.

Operating Revenues

The Utility’s electric and natural gas operating revenues increased by $2.7 billion, or 13%, in 2023 compared to 2022. These increases were primarily due to:

•approximately $1.5 billion in increased base revenues authorized in the 2023 GRC in 2023;

•approximately $740 million in revenues authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below) in 2023;

•approximately $585 million in revenues authorized in the 2020 WMCE proceeding in 2023;

•approximately $550 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in 2023;

•an increase of approximately $360 million in revenues to recover the costs associated with RUBA in 2023. These revenues and associated costs are passed through to customers and do not impact net income. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8); and

•additional revenues as authorized through the FERC formula rate in 2023.

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Partially offset by:

•a decrease in revenues to recover the cost of electricity procurement (which decreased by approximately $310 million), the cost of natural gas (which decreased by approximately $350 million) and the cost of public purpose programs (which decreased by approximately $70 million). These costs are passed through to customers and do not impact net income. (See “Cost of Electricity” and “Operating and Maintenance” below);

•the recognition of approximately $310 million in revenues related to the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K) in 2022;

•a decrease of approximately $270 million in revenues to recover the costs associated with RTBA in 2023. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8); and

•the recognition of approximately $180 million in revenues related to the final decision approving $356 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its gas transmission and storage system (see “2015 Gas Transmission and Storage Rate Case” in Regulatory Matters in the 2022 Form 10-K) in 2022.

Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly with third parties. The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.

The cost of electricity decreased by $313 million in 2023 as compared to 2022. This was primarily the result of decreased customer demand volumes for the Utility’s bundled electric services, lower purchased power quantities due to contract expirations and higher net energy sales. These decreases were partially offset by increased fuel costs due to higher natural gas prices occurring in early 2023.

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8.

The cost of natural gas decreased by $346 million in 2023 as compared to 2022. This was primarily due to favorable price risk management results during the high natural gas price period in early 2023. This decrease was partially offset by an increase in cap-and-trade program compliance costs in 2023.

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Operating and Maintenance

The Utility’s operating and maintenance expenses increased by $2.2 billion, or 22%, in 2023 compared to 2022. These increases were primarily due to:

•the recognition of approximately $485 million in previously deferred expenses as a result of the 2023 GRC in 2023;

•the recognition of approximately $720 million in previously deferred expenses authorized in the 2021 WMCE proceeding (see “2021 WMCE Application” below) in 2023;

•the recognition of approximately $420 million in previously deferred expenses authorized in the 2020 WMCE proceeding in 2023;

•the recognition of approximately $550 million in interim rate relief authorized in the 2022 WMCE proceeding (see “2022 WMCE Application” below) in 2023;

•an increase of approximately $360 million in costs associated with RUBA in 2023. These costs are passed through to customers and do not impact net income. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8); and

•the recognition of $50 million in expenses in 2023, related to the civil stipulated judgement filed on May 31, 2023, by the Utility and the Shasta County District Attorney’s Office (“Shasta D.A.”) for the Shasta D.A. to dismiss with prejudice all criminal charges against the Utility in connection with the 2020 Zogg fire.

Partially offset by:

•a decrease of approximately $350 million in insurance costs related to the Utility’s adoption of self-insurance;

•the recognition of approximately $310 million of previously deferred expenses, which were authorized by the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” in Regulatory Matters in the 2022 Form 10-K) in 2022;

•the recognition of $85 million in expenses related to the Kincade SED Settlement (as defined in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K) in 2022;

•the recognition of $77 million in charges as a result of its voluntary separation program in 2022;

•the recognition of $55 million in expenses related to the Kincade Stipulation and the Dixie Stipulation (each as defined in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2022 Form 10-K) in 2022;

•a decrease of approximately $70 million in pass-through costs related to public purpose programs in 2023. These costs are passed through to customers and do not impact net income (see “Operating Revenues” above); and

•increased operating cost efficiencies in 2023.

SB 901 Securitization Charges, Net

The Utility’s SB 901 securitization charges, net increased by $659 million, or 108%, in 2023 compared to 2022. These increases were due to the recognition of $1.3 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023, compared to charges of $608 million in 2022. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below.

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Wildfire-Related Claims, Net of Recoveries

Costs related to wildfires decreased by $173 million, or 73%, in 2023 compared to 2022. The Utility recognized pre-tax charges of $225 million related to the 2019 Kincade fire, $100 million related to the 2022 Mosquito fire, $25 million related to the 2021 Dixie fire, and $25 million related to the 2020 Zogg fire in 2022. These charges were partially offset by $95 million of probable recoveries through insurance and the WEMA related to the 2022 Mosquito fire and $25 million in probable recoveries through the Wildfire Fund related to the 2021 Dixie fire. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire and $100 million related to the 2019 Kincade fire in 2023. These charges were partially offset by $425 million of probable recoveries through the Wildfire Fund, insurance, and the WEMA related to the 2021 Dixie fire.

In addition to the probable wildfire-related recoveries noted above, the Utility has recorded $99 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims. See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Wildfire Fund Expense

The Utility’s Wildfire Fund expense increased by $90 million, or 19%, in 2023 compared to 2022. These increases were primarily due to accelerated amortization of the Wildfire Fund asset recorded in 2023 as a result of the $425 million Wildfire Fund receivable accrued in relation to the 2021 Dixie fire, with no similar amounts recorded in 2022. See Note 2 and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses decreased by $118 million, or 3%, in 2023 compared to 2022. These decreases were primarily due to a reduction in nuclear and gas storage decommissioning expenses as a result of the 2021 NDCTP and 2023 GRC final decisions. Depreciation expense due to plant growth was mostly offset by lower depreciation rates authorized in the 2023 GRC final decision.

Interest Income

The Utility’s interest income increased by $431 million, or 266%, in 2023 compared to 2022. These increases were primarily due to higher interest rates earned on regulatory balancing accounts.

Interest Expense

The Utility’s interest expense increased by $827 million, or 50%, in 2023 compared to 2022. These increases were primarily due to the issuance of additional long-term debt, an increase in interest rates on variable-rate debt and an increase in interest rates associated with regulatory balancing accounts.

Other Income, Net

The Utility’s other income, net decreased by $302 million, or 51%, in 2023 compared to 2022. These decreases were primarily due to pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

Income Tax Benefit

The Utility’s income tax benefit increased by $255 million, or 21%, in 2023 compared to 2022. These increases were primarily due to a benefit recognized related to the Fire Victim Trust’s sale of PG&E Corporation common stock in 2023.

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The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:

(1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA.

(3) Includes the tax effect of the Fire Victim Trust’s sale of PG&E Corporation common stock. See “Tax Matters” above and Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Nuclear Operations

Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of Diablo Canyon’s generation to the California electricity market and impact the Utility’s performance-based disbursements. For more information, see “Extension of Diablo Canyon Operations” below. Management analyzes capacity factors by comparing Diablo Canyon’s actual generation to forecasted annual capacity factors, which reflect planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms.

The Utility manages its scheduled refueling outages with the objective of minimizing their duration and maintaining high nuclear generating capacity factors, resulting in a stable generation base for the Utility’s wholesale and retail power marketing activities. During scheduled refueling outages, the Utility performs maintenance and equipment upgrades to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the years ended December 31, 2023 and 2022, Diablo Canyon achieved an average capacity factor of 90%.

In addition to the maintenance and equipment upgrades performed by the Utility during scheduled refueling outages, the Utility has extensive operating and security procedures in place to assure the safe operation of Diablo Canyon. The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short-term and in the long-term.

PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. The CPUC has granted the Utility a temporary waiver from compliance with its authorized regulatory capital structure until June 2025. The Utility is on track to comply with its authorized regulatory capital structure when the waiver terminates.

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PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation common stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.

Additionally, due to its existing tax attributes, PG&E Corporation does not expect to be a significant federal cash taxpayer until at least 2029. See “Tax Matters” above and “Inflation Reduction Act” in Legislative and Regulatory Initiatives below for a discussion of events that could limit PG&E Corporation’s ability to use its net operating losses.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

As of December 31, 2023, PG&E Corporation and the Utility had access to approximately $3.1 billion of total liquidity comprised of approximately $442 million of Utility’s cash and cash equivalents, $193 million of PG&E Corporation’s cash and cash equivalents and $2.5 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Credit Ratings

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s credit rating remains below investment grade, the Utility generally does not receive unsecured credit from its energy procurement counterparties and it may be required to increase its collateral postings if its credit rating is downgraded.

Restrictive Debt Covenants

PG&E Corporation’s and the Utility’s credit agreements contain various financial covenants. PG&E Corporation and the Utility must maintain a total consolidated debt to total consolidated capitalization ratio of no more than 70% and 65% for PG&E Corporation and the Utility, respectively, as of the end of each fiscal quarter. In addition, if revolving loans are outstanding under the Corporation Revolving Credit Agreement as of the last day of a fiscal quarter, PG&E Corporation must comply with a fixed charge coverage covenant.

The failure to comply with the financial covenants contained in these financing arrangements could result in an event of default and the acceleration of the loans under the financing arrangements. As of December 31, 2023, PG&E Corporation and the Utility remain in compliance with all financial covenants.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

As of December 31, 2023, the Utility had contributed $340 million to its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance, of which approximately $8 million was classified as Restricted cash due to minimum capital and surplus requirements (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8).

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Financial Resources

Equity Financings

PG&E Corporation does not plan to issue any equity in 2024, except for employee compensation purposes. PG&E Corporation and the Utility are pursuing the potential sale of a minority interest in Pacific Generation. (See “Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets” below.) Factors that could affect PG&E Corporation’s planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, its share price, its earnings, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

Debt Financings

The Utility generally issues first mortgage bonds and secured debt to meet its long-term debt funding requirements.

On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The net proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.70% First Mortgage Bonds due 2053. The Utility intends to disburse or allocate an amount equal to the net proceeds to finance or refinance, in whole or in part, new or existing eligible green projects and eligible social projects. Pending full disbursement or allocation of an amount equal to the net proceeds from this offering to finance or refinance eligible projects, the Utility expects to use the net proceeds for the repayment of borrowings outstanding under the Utility Revolving Credit Agreement.

On June 5, 2023, the Utility completed the sale of (i) $850 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.15 billion aggregate principal amount of 6.400% First Mortgage Bonds due 2033, and (iii) $500 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The net proceeds were used for the repayment of $375 million aggregate principal amount of 3.25% First Mortgage Bonds due June 15, 2023 and for general purposes, including for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility used the remaining net proceeds to repay the $500 million aggregate principal amount of 4.25% First Mortgage Bonds due August 1, 2023 at maturity.

On November 8, 2023, the Utility completed the sale of $800 million aggregate principal amount of 6.950% First Mortgage Bonds due 2034. The Utility used the net proceeds to repay a portion of the $900 million aggregate principal amount of 1.70% First Mortgage Bonds due November 15, 2023 at maturity.

Credit Facilities and Term Loans

As of December 31, 2023, PG&E Corporation and the Utility had $500 million and $2.0 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

On April 18, 2023, the Utility amended its existing term loan agreement to extend the maturity of the $125 million 364-day tranche loan thereunder from April 19, 2023 to April 16, 2024. The 364-day tranche loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375%, or (2) the alternate base rate plus an applicable margin of 0.375%.

On June 9, 2023, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, extend the scheduled termination date from September 30, 2024 to June 9, 2025 and increase the low end of the facility limit from $1.0 billion to $1.25 billion.

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On June 22, 2023, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date to June 22, 2028 (subject to two one-year extensions at the option of the Utility), (ii) increase the maximum letter of credit sublimit to $2.0 billion, and (iii) increase the uncommitted incremental facility to up to $1.0 billion.

On November 15, 2023, the Utility entered into a Bridge Term Loan Credit Agreement (the “Bridge Term Loan Credit Agreement”), pursuant to which the lenders made available to the Utility term loans in the aggregate principal amount equal to $2.1 billion (the “Term Loans”). The Utility borrowed the entire amount of the Term Loans on November 15, 2023. The Term Loans have a maturity date of August 15, 2024. The Utility is required to prepay loans outstanding under the Bridge Term Loan Credit Agreement, subject to certain exceptions, with 100% of the net cash proceeds received by the Utility from the issuance or incurrence of any debt by its subsidiary, Pacific Generation. Borrowings under the Bridge Term Loan Credit Agreement bear interest based on the Utility’s election of either (1) Term SOFR (as defined in the Bridge Term Loan Credit Agreement) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25% or (2) the alternate base rate plus an applicable margin of 0.25%.

PG&E Corporation

On June 22, 2023, PG&E Corporation amended its existing revolving credit agreement to, among other things, extend the maturity date to June 22, 2026 (subject to two one-year extensions at the option of PG&E Corporation).

On December 8, 2023, PG&E Corporation entered into an amendment to its existing term loan agreement to, among other things, extend the maturity date from June 23, 2025 to June 23, 2027, and reduce the applicable margin from 300 basis points to 250 basis points. The term loan bears interest based on Adjusted Term SOFR plus an applicable margin of 2.50%.

On December 4, 2023, PG&E Corporation used the net proceeds from the Convertible Notes, together with cash on hand, to prepay $2.15 billion of aggregate principal amount of the term loans under the term loan agreement. See “Convertible Notes” below. In addition, on December 8, 2023, PG&E Corporation used other available funds to prepay $11 million of aggregate principal amount of the term loans under the term loan agreement. As a result of the early extinguishment of these term loans, PG&E Corporation recognized $26 million of unamortized discount and issuance costs in Interest expense in the Consolidated Financial Statements for the year ended December 31, 2023. The outstanding aggregate principal amount of term loans outstanding after giving effect to these prepayments and the amendment to the term loan agreement is $500 million.

For more information, see “Credit Facilities and Term Loans” in Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

Convertible Notes

On December 4, 2023, PG&E Corporation issued $2.15 billion aggregate principal amount of 4.25% Convertible Senior Secured Notes due December 1, 2027 (the “Convertible Notes”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from this offering were approximately $2.12 billion, after deducting the Initial Purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

For more information, see “Convertible Notes” in Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

Other Financings

PG&E Corporation and the Utility are pursuing additional financing sources in order to more efficiently finance their operations.

The Utility is seeking financing through the Energy Infrastructure Reinvestment category of the DOE’s Clean Energy Financing Program to help fund California’s clean energy transition.

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On February 20, 2024, the Utility entered into an agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets to be constructed or otherwise not yet in service. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years. The transactions contemplated by the agreement are subject to FERC and CPUC approval.

Dividends

Utility

On each of December 15, 2022, February 16, 2023, May 18, 2023, September 14, 2023, and December 13, 2023, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which were paid on February 15, 2023, May 15, 2023, August 15, 2023, November 15, 2023, and February 15, 2024, respectively. In addition, on February 14, 2024, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on May 15, 2024, to holders of record as of April 30, 2024.

On each of February 16, May 18, September 14, and December 13, 2023, the Board of Directors of the Utility declared common stock dividends of $425 million, $450 million, $450 million, and $450 million, which were paid to PG&E Corporation on February 28, June 21, September 29, and December 20, 2023, respectively.

PG&E Corporation

On November 27, 2023, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, totaling $21 million, which was paid by January 16, 2024, to holders of record as of December 29, 2023.

On February 14, 2024, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.01 per share, payable on April 15, 2024, to holders of record as of March 28, 2024.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for 2023 and 2022.

See “Liquidity and Financial Resources” in Item 7 of the 2022 Form 10-K for discussion of the Utility’s cash flows for 2022 compared to 2021.

The Utility’s cash flows were as follows:

Operating Activities

Net cash provided by operating activities increased by $1.3 billion, or 33%, in 2023 compared to 2022. The increases were primarily due to wildfire insurance premium payments of $778 million and a payment made to the Fire Victim Trust of $592 million in 2022, with no similar payments made in 2023.

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation and amortization that do not require the use of cash. The Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base.

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Future cash flow from operating activities will be affected by various factors, including:

•the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, including funds available from self-insurance (see “2023 General Rate Case” in the “Regulatory Matters” section below for more information), the Wildfire Fund, and regulatory recoveries;

•the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8);

•the timing and amount of costs in connection with the 2020-2022 and 2023-2025 WMPs and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and

•the timing and amount of electric commodity price volatility and differences between commodity costs and revenue collections.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements.

Investing Activities

The following table summarizes changes in key components of the Utility’s investing cash flows for the year ended December 31, 2023, compared to December 31, 2022.

Net cash used in investing activities decreased by $907 million, or 9%, in 2023 compared to 2022. The decrease was primarily due to a $1.3 billion decrease in purchases, net of proceeds, related to customer credit trust investments in 2023. This decrease was partially offset by a $145 million intercompany loan repayment in 2022, with no similar transaction in 2023, and a $130 million increase in capital expenditures, primarily due to new customer connections and responses to winter storm events.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur $10.4 billion of capital expenditures in 2024. Additionally, future cash flows used in investing activities could be impacted by the timing and amount of contributions to the self-insurance captive (see “Self-Insurance” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8) and to the customer credit trust, including $1.0 billion to be contributed in 2024 (see Note 5 of the Notes to the Consolidated Financial Statements in Item 8).

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Financing Activities

The following table summarizes changes in key components of the Utility’s financing cash flows for the year ended December 31, 2023, compared to December 31, 2022.

Net cash provided by financing activities decreased by $2.9 billion, or 42%, in 2023 compared to 2022. The decreases were primarily due to:

•$8.4 billion in proceeds from AB 1054 and SB 901 recovery bonds in 2022, with no similar transactions in 2023;

•$312 million in proceeds related to the DWR loan in 2022, with no similar transaction in 2023; and

•a $245 million decrease in net borrowing under credit facilities.

Partially offset by:

•a $3.2 billion decrease in repayments related to short-term and long-term debt;

•a $1.2 billion increase in borrowings related to long-term debt; and

•a $2.1 billion increase in borrowings under term loan credit facilities.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments (see “Contractual Repayment Schedule” in Note 4 of the Notes to the Consolidated Financial Statements in Item 8). Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and in “Regulatory Matters” below that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing and outcome of the following applications.

During year ended December 31, 2023 and through the date of this filing, key updates to regulatory and legislative matters were as follows:

•In February 2024, the CPUC issued a final resolution approving an Administrative Consent Order and Agreement between the SED and the Utility regarding the 2021 Dixie fire.

•In December 2023, the NRC deemed the Utility’s application for license renewal sufficient, which allows continued operations at Diablo Canyon past the plant’s current licenses, and the CPUC approved extended operations at Diablo Canyon.

•In December 2023, the OEIS issued a final decision approving the Utility’s 2023-2025 WMP, which the CPUC ratified in February 2024. The OEIS issued a safety certificate for the Utility in January 2024.

•In December 2023, the CPUC approved the Utility’s advice letter indicating that the cost of capital adjustment mechanism had been triggered and increased the Utility’s ROE from 10.0% to 10.7% and its cost of long-term debt from 4.31% to 4.66%.

•In November 2023, the CPUC issued a final decision in the Utility’s 2023 GRC, which authorized the Utility’s base revenues for the period of 2023 through 2026. For 2023, the revenue requirement was $13.52 billion, excluding self-insurance.

•Since January 2023, the Utility has filed cost recovery applications requesting aggregate cost recovery of approximately $4.7 billion of recorded expenditures. In terms of interim rate relief, the CPUC has issued a PD for $516 million and a final decision for $1.1 billion. In terms of final cost recovery, the CPUC has authorized aggregate revenue requirements of $1.76 billion, which does not include costs that remain to be addressed.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs. While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs.

In recent years, the amount of the costs recorded in these accounts has increased. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2023, the Utility had recorded an aggregate amount of approximately $4.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of December 31, 2023. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

(1) The revenue requirement request amounts do not include interest.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2021 WMCE Application

On September 16, 2021, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.6 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.47 billion (the “2021 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2020.

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The Utility’s requested revenue requirement includes amounts recorded to the VMBA of $592 million, the CEMA of $535 million, the WMBA of $149 million, and other memorandum accounts.

On August 10, 2023, the CPUC approved a settlement agreement among the Utility and intervenors pursuant to which the Utility began collecting a revenue requirement of $721 million over 24 months beginning September 1, 2023. The settlement agreement did not address the Utility’s revenue requirement of $592 million associated with costs recorded to the VMBA, for which cost recovery will be determined separately by the CPUC.

2022 WMCE Application

On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021.

The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures. On June 8, 2023, the CPUC adopted a final decision granting the Utility’s interim rate relief of $1.1 billion to be recovered over 12 months, which went into effect July 1, 2023. The remaining $224 million will be recovered to the extent it is approved after the CPUC issues a final decision. See “2022 WMCE Interim Rate Relief Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

On December 22, 2023, the Utility filed an unopposed joint settlement with intervenors for an additional $70 million revenue requirement, which is incremental to the previously approved interim rate relief. If the CPUC adopts the settlement agreement, it would resolve all costs recorded to accounts other than the VMBA and the WMBA. The settlement agreement did not address the Utility’s revenue requirement request of $916 million associated with costs recorded to the VMBA or the WMBA, for which cost recovery will be determined separately by the CPUC.

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On June 23, 2023, the ALJ revised the procedural schedule to indicate that a PD would be issued by the second quarter of 2024.

2023 WMCE Application

On December 1, 2023, the Utility filed an application with the CPUC requesting cost recovery of approximately $2.18 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.86 billion (the “2023 WMCE application”). The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2022.

The recorded expenditures consist of $1.6 billion in expenses and $559 million in capital expenditures. Of these amounts, approximately 15% of expense, or $239 million and 30% of capital expenditures, or $167 million, relate to the Utility’s response to the 2022-2023 extreme winter storms CEMA event.

In connection with the 2023 WMCE application, the Utility also requested interim rate relief of $1.46 billion to be recovered over 12 months beginning March 1, 2024. The remaining $399 million would be recovered after the CPUC issues a final decision. On January 29, 2024, the Utility filed a supplemental motion for interim rate relief based on an agreement with the Public Advocates Office of the CPUC. Under the supplemental motion, the Utility would recover $944 million over 17 months, at least $500 million of which would be recovered in 2024. Following the 17-month period, the Utility would recover the remaining $515 million amount up to $1.46 billion.

The Utility has requested a final decision in the proceeding by the end of 2024 or, if the supplemental motion for interim rate relief is granted, the second quarter of 2025.

Wildfire and Gas Safety Costs Recovery Application

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table:

In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On February 1, 2024, the CPUC issued a PD that would authorize the Utility to recover $516 million in interim rates to be recovered over 12 months.

The ALJ has adopted a schedule that would result in a final decision on the wildfire mitigation costs by November 2024 and a final decision on the gas safety and electric modernization costs by June 2025.

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Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS and the CPUC approve guidelines (see “SB 884 10-Year Distribution Undergrounding Program” below).

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

2023 General Rate Case

Phase 1

On June 30, 2021, the Utility filed its 2023 GRC application with the CPUC. The 2023 GRC combined what had historically been separated into the GRC and GT&S. In the 2023 GRC, the CPUC determined the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 (the “GRC period”) to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, and electricity, natural gas and power purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. In the application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Between August 2021 and December 2022, the Utility served various updates to its 2023 GRC testimony.

On January 12, 2023, the CPUC approved a settlement agreement among the Utility and two parties to the proceeding pursuant to which the Utility’s wildfire liability insurance will be entirely based on self-insurance beginning in 2023. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

On November 17, 2023, the CPUC issued a final decision on Phase 1, Tracks 1 and 2.

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Track 1

The Utility is authorized to collect through rates the approved revenue requirement increases beginning January 1, 2024 and to amortize the incremental revenue increases related to 2023 for 24 months over the period of January 1, 2024 through December 31, 2025.

The following table compares the Track 1 revenue requirements authorized in the final decision with the revenue requirement authorized for 2022 in the 2020 GRC and 2019 GT&S proceedings and the revenue requirement requested in the Utility’s application as amended and updated:

(1) Request has been adjusted to exclude amounts related to self-insurance.

The final decision also grants 50% of the Utility’s requested increase in escalation rates.

Track 2

On July 22, 2022, the Utility submitted a request for Track 2 of the GRC proceeding, requesting cost recovery of recorded expenditures related primarily to the safety and reliability of the Utility’s gas transmission and storage system incurred from January 2015 to December 2021. The recorded expenditures consist of $209 million in expenses and $129 million in capital expenditures. On January 6, 2023, the Utility and the Public Advocates Office of the CPUC filed a motion for approval of a settlement agreement for all amounts at issue in the second track of the proceeding. In the motion, the parties requested that the CPUC approve $183 million in expense and $127 million of capital expenditures for recovery through rates.

The final decision approved the settlement agreement in Track 2 of the proceeding. The settlement agreement results in a revenue requirement of $221 million to be recovered over 2023 and 2024.

Rate Base and Capital Additions

The following table compares the weighted-average GRC rate base that the final decision authorizes with the weighted-average GRC rate base requested in the Utility’s application as amended and updated:

The final decision authorizes funding for 1,230 miles of undergrounding and 778 miles of covered conductor for the GRC period. The Utility most recently had requested 2,000 miles of undergrounding and 320 miles of covered conductor for the GRC period.

The final decision denies cost recovery through this GRC for a number of costs but gives the Utility an opportunity to seek recovery of these costs in future proceedings to the extent they are eligible for cost recovery: capital costs of $0.9 billion associated with moving the Utility’s corporate headquarters to Oakland, California; capital costs of $1.2 billion for rebuilding electric and gas infrastructure following the 2018 Camp fire; capital costs of $1.3 billion tracked in certain wildfire mitigation and other memorandum accounts; and capital costs of $0.7 billion for the gas advanced metering infrastructure module replacement project. These costs and the corresponding rate base have been removed from the final decision.

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Additional Capacity Phase

On September 15, 2023, the Utility served opening testimony proposing to establish a balancing account consistent with SB 410 to record and recover costs of electric distribution capacity additions and new non-residential electric distribution extension work incremental to the forecasts of the Utility’s Phase 1 2023 GRC. The Utility proposed to record to the balancing account actual capital expenditures for these programs, with recorded costs for a given year to be recovered through the following year’s rates and subject to reasonableness review in the 2027 GRC application. Costs recorded to the account would be subject to an annual cap, which is designed to effectuate an electric distribution average rate impact of no more than 2.5%, calculated based on the Utility’s adopted GRC electric distribution revenue requirement for the applicable year beginning in 2024. Based on the final decision on Phase 1, the cap would equate to approximately $183 million of revenue requirement and incremental capital expenditures of approximately $1.26 billion. A PD on the balancing account proposal is expected in the second quarter of 2024.

Cost of Capital Proceedings

2023 Cost of Capital Application

On December 19, 2022, the CPUC issued a final decision adopting a new cost of capital including ratemaking capital structure (i.e., the relative weightings of common equity, preferred equity, and debt for ratemaking), ROE, cost of preferred stock, and cost of debt for the Utility’s electric generation, electric distribution, natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2023. On January 10, 2023, the CPUC issued a decision correcting certain typographical errors in the final decision. On December 14, 2023, certain intervenors filed a petition for modification requesting that the 2023 Cost of Capital decision be modified to, among other things, suspend application of the cost of capital adjustment mechanism pending further CPUC decision. On January 16, 2024, the Utility submitted its response.

The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt. The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The decision deferred consideration of the proposal to a second phase of the proceeding. On September 20, 2023, the assigned ALJ issued a ruling identifying the remaining issues to be addressed in the second phase of the proceeding and outlining a proposed process and schedule to resolve the remaining issues.

Cost of Capital Adjustment Mechanism

On October 13, 2023, the Utility filed an advice letter indicating that the cost of capital adjustment mechanism had been triggered and requesting to increase the Utility’s ROE from 10.0% to 10.7% and its cost of long-term debt from 4.31% to 4.66%. On December 22, 2023, the CPUC approved the Utility’s advice letter. As a result, the Utility is authorized to collect a revenue requirement of $328 million, based on the 2023 GRC rate base, effective January 1, 2024. On January 12, 2024, several intervenors submitted a request for the CPUC to review the approval.

The Utility’s annual cost of capital adjustment mechanism provides that in any year during the applicable cost of capital period in which the difference between (i) the average Moody’s Baa utility bond rates (as measured in the 12-month period from October of the prior year through September of the year in which the mechanism could trigger (the “Index”)) and (ii) 4.37% (based on the 2023 Cost of Capital decision) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility is to initiate this adjustment mechanism by filing an advice letter on or before October 15 of the year in which the mechanism is triggered, to become effective on January 1 of the next year. For the period from October 1, 2022 to September 30, 2023, the Index averaged 141 basis points above the Utility’s cost of capital benchmark rate of 4.37%, triggering the adjustment mechanism for the rest of the Cost of Capital period. Starting on January 1, 2024, the Utility’s authorized ROE increased from 10.0% to 10.7%, its authorized cost of long-term debt increased from 4.31% to 4.66%, and the benchmark has been updated to 5.78%.

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Transmission Owner Rate Cases

Transmission Owner Rate Case for 2024 (the “TO21” rate case)

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. In the filing, the Utility forecasts a 2024 retail electric transmission revenue requirement of $2.83 billion. The proposed amount reflects an approximately 11% decrease over the current rate year 2023 retail revenue requirement of $3.18 billion, due in part to a refund to customers (see “Transmission Owner Rate Case Revenue Subject to Refund” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8) and the transaction to lease entitlements associated with certain transmission assets (see “Liquidity and Financial Resources - Other Financings” above). The Utility made investments of approximately $1.22 billion in 2023 and forecasts that it will make investments of approximately $1.43 billion in 2024 for various capital projects to be placed in service before the end of 2024. The Utility has requested that FERC approve a 12.37% base ROE as well as a 0.5% adder for its participation in the CAISO. The TO21 filing also addresses the Utility’s capital structure and several new issues including wildfire self-insurance recovery from transmission customers. On December 29, 2023, the FERC issued an order accepting the TO21 filing subject to refund, establishing a January 1, 2024 effective date, and establishing a settlement and hearing process, but rejecting the 0.5% ROE adder for participation in the CAISO. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s rejection of the 0.5% ROE adder.

Other Regulatory Proceedings

2020-2022 Wildfire Mitigation Plans

On February 26, 2023, the OEIS issued its final Annual Report on Compliance (“ARC”) for the Utility’s 2020 WMP. In the final ARC, the OEIS found that the Utility undertook significant efforts to reduce its wildfire risk and, in many instances, achieved its stated objectives and targets, but did not substantially comply with the WMP during the 2020 compliance period. On March 24, 2023, the Utility filed a writ in the California superior court seeking judicial review of the OEIS ARC on the grounds that the OEIS failed to utilize the compliance evaluation criteria adopted by the CPUC. If the court sustains the ARC’s finding that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance. PG&E Corporation and the Utility cannot reasonably estimate whether they will incur a loss in connection with the ARC or the amount of any such loss, as the writ is pending in state court and because any penalty issued by the CPUC depends upon various factors.

2023-2025 Wildfire Mitigation Plan

On March 27, 2023, the Utility submitted the 2023-2025 WMP. The 2023-2025 WMP addresses the Utility’s wildfire safety programs and initiatives focused on reducing the potential for catastrophic wildfires related to electrical equipment and reducing the customer impact of EPSS and PSPS events. On June 22, 2023, the OEIS issued a revision notice requiring the Utility to address eight critical issues. The Utility submitted the response to the revision notice on August 7, 2023. On September 27, 2023, the Utility submitted additional information on the revision notice response to the OEIS. On December 29, 2023, the OEIS issued a final decision approving the Utility’s 2023-2025 WMP. On February 15, 2024, the CPUC ratified the OEIS’s approval.

The Utility expects to submit updates to the WMP for 2025 on April 1, 2024, as directed by the OEIS.

OIR to Revisit Net Energy Metering Tariffs

On December 19, 2022, the CPUC issued a final decision in the rulemaking proceeding to develop a successor to the NEM tariffs. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, deferred this issue to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for residential electric customers. The decision does, however, clarify that fixed charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

On January 18, 2023, intervenors filed an application for rehearing. On June 30, 2023, the CPUC denied the application.

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On May 4, 2023, intervenors filed in the California Court of Appeal a petition for writ of review of the CPUC’s decision. On December 20, 2023, the appellate court affirmed the CPUC’s decision.

Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets

On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter.

On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation. On May 31, 2023, the FERC issued an order approving the transfer of FERC-jurisdictional assets from the Utility to Pacific Generation.

Self-Reports to the CPUC

The Utility self-reports potential violations of certain requirements to the CPUC. The Utility could face penalties, enforcement actions, or other adverse legal or regulatory consequences for these potential violations, including under the EOEP. For more information about the EOEP, see “PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process” in Item 1A. Risk Factors. The Utility is unable to predict the likelihood and the amount of potential fines or penalties, if any, related to these matters.

Electric Asset Inspections

The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility’s 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility’s asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets.

On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022 and February 1, 2024, the Utility submitted updates to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures.

The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

Extension of Diablo Canyon Operations

On September 2, 2022, SB 846 became law. SB 846 supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Under the legislation, the Utility would continue to operate Diablo Canyon on behalf of all CPUC-jurisdictional LSEs, and all customers of those LSEs would be responsible for the cost of extended operations.

The key steps to continued operations are NRC license renewal and approvals from California state agencies, including the CPUC, CEC, California State Lands Commission, California Coastal Commission, and other state agencies. As set forth below, many of these approvals have been received, but if any such approval is not received, the Utility would retire Unit 1 in 2024 and Unit 2 in 2025 as previously approved by the CPUC.

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On February 28, 2023, and in consultation with the CAISO and CPUC, the CEC determined that it is prudent to extend the operation of Diablo Canyon to support electric system reliability through 2030.

The Utility leases land from the state for the water intake structure, breakwaters, cooling water discharge channel, and other structures on state land associated with Diablo Canyon. On June 5, 2023, the California State Lands Commission approved an extension of the Utility’s lease at Diablo Canyon through October 31, 2030.

On August 15, 2023, the California State Water Resources Control Board approved the Utility’s plan for once-through cooling at Diablo Canyon.

On September 26, 2023 the CEC issued a draft report concluding that no suitable supply-side resources can be brought online as alternatives to Diablo Canyon’s energy and capacity output prior to the planned retirement dates in 2024 and 2025.

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On December 19, 2023, the NRC deemed the application sufficient, which allows continued operations at Diablo Canyon past the plant’s current licenses.

On December 14, 2023, the CPUC approved extended operations at Diablo Canyon until October 31, 2029 for Unit 1 and October 31, 2030 for Unit 2. The approval is subject to the following conditions: (1) the NRC continues to authorize Diablo Canyon operations; (2) the loan agreement authorized by SB 846 is not terminated; and (3) the CPUC does not make a future determination that Diablo Canyon extended operations are imprudent or unreasonable.

Application for Third AB 1054 Securitization Transaction

AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge.

On August 10, 2023, the Utility filed an application with the CPUC seeking authorization for a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the first quarter of 2024, which it subsequently extended through the second quarter of 2024. The $1.38 billion reflected $187 million of recorded capital expenditure amounts that were approved by the CPUC in the 2020 GRC, $350 million capital expenditure amounts that were approved by the CPUC in the 2020 WMCE proceeding, and up to $843 million forecasted capital expenditure amounts approved in the 2023 GRC. These amounts were not included in the first or second securitization transactions. The final amount to be financed using securitization would be based on actual recorded and authorized capital expenditures incurred by the Utility prior to the securitization transaction and not to exceed the remaining $1.38 billion of the Utility’s AB 1054 allocation. If approved, the Utility anticipates the transaction will result in the last securitization of AB 1054 capital expenditure amounts subject to the equity rate base exclusion.

The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds. The application also requested that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC, 2020 WMCE proceeding, and 2023 GRC revenue requirements following the issuance of the recovery bonds.

The Utility has requested a financing order to be issued within 180 days after the filing of the application on August 10, 2023. On November 22, 2023, the Utility filed opening briefs to update the capital expenditures forecast for the 2023 GRC final decision and extend the forecast capex period through the second quarter of 2024. On February 15, 2024, the CPUC issued a final decision approving the Utility’s application.

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SB 884 10-Year Distribution Undergrounding Program

On November 9, 2023, the Safety and Policy Division of the CPUC issued a resolution which, if adopted, would establish an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addresses the process and requirements for the CPUC's review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. The draft resolution is currently on the CPUC’s March 7, 2024 meeting agenda.

On December 13, 2023, the OEIS issued a request for comments as part of its ongoing process to develop guidelines for its program. The Utility and other stakeholders submitted comments on January 8, 2024 and reply comments on January 18, 2024.

The Utility anticipates that the OEIS and the CPUC will issue final guidelines in early 2024. The Utility expects to submit its undergrounding plan to the OEIS in mid-2024 before submitting its cost application to the CPUC, as directed in Public Utilities Code Section 8388.5.

LEGISLATIVE AND REGULATORY INITIATIVES

Inflation Reduction Act

In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the IRS have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility continue to evaluate the totality of the law, the regulations issued in connection with it, and its impact on qualifying investments. As of December 31, 2023, the law did not have a material impact on the PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

Revenue Procedure 2023-15

On April 14, 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method for determining natural gas repairs deductions for income tax purposes. PG&E Corporation and the Utility are continuing to evaluate the impact of the revenue procedure.

Senate Bill 410

On October 7, 2023, SB 410 became law. SB 410 authorizes electrical corporations to request, and requires the CPUC to approve, a ratemaking mechanism to recover distribution line, substation capacity, and new business investments that exceed the GRC annual authorized revenue requirements, up to an annual cap. Amounts recorded to the related balancing account would be reviewed for reasonableness in the following GRC. See “Regulatory Matters - 2023 General Rate Case” above for more information.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public.  These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See Item 1A. Risk Factors, “Environmental Regulation” in Item 1 and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit. The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes.

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Commodity Price Risk

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices do not affect earnings. Such fluctuations, however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility does not have a balancing account for costs in excess of its revenue requirement for natural gas transportation and storage service to non-core customers. The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $4 million and $3 million at December 31, 2023 and 2022, respectively. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities.

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2023 and 2022, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $57 million and $54 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas and related services, then the Utility may find it necessary to procure electricity or gas at current market prices or seek alternate services, which may be higher than the contract prices.

The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility executes many energy contracts under master commodity enabling agreements that may require security. Security may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Security or performance assurance may be required from the Utility or counterparties when current net receivables or payables and exposure exceed contractually specified limits.

The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties:

(1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.

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CRITICAL ACCOUNTING ESTIMATES

The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting estimates due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting estimates and their key characteristics are outlined below.

Contributions to the Wildfire Fund

The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the DWR charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs, and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for a 10-year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs through rates. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service area classified as HFTDs and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million).

On the Emergence Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. The other large electric IOUs made their initial contributions to the Wildfire Fund in September 2019. In December 2022 and 2023, the Utility made its fourth and fifth annual contributions of $193 million each to the Wildfire Fund. As of December 31, 2023, PG&E Corporation and the Utility have five remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below.

As of December 31, 2023, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $750 million in Other noncurrent liabilities, $450 million in Current assets - Wildfire Fund asset, and $4.3 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2023 and 2022, the Utility recorded amortization and accretion expense of $567 million and $477 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Consolidated Balance Sheets are discounted to the present value using the 10-year U.S. treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.

AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Initial use of five years of historical data, with average annual statewide claims or settlements of approximately $6.5 billion versus 12 years of historical data, with average annual statewide claims or settlements of approximately $2.9 billion, would have resulted in a six year amortization period. As of December 31, 2023, a 5% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period by five years assuming greater effectiveness and would decrease the amortization period by four years assuming less effectiveness.

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Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by participating electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires and determination of any amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and as required by additional information, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that a participating utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such acceleration of the amortization of the asset could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service area. There were fires in the Utility’s and other participating utilities’ service areas since July 12, 2019, including fires for which the cause is unknown, which may in the future be determined to be covered by the Wildfire Fund. PG&E Corporation and the Utility recorded $102 million and $6 million of accelerated amortization, reflected in Wildfire Fund expense for the years ended December 31, 2023 and 2022, respectively. As of December 31, 2023, PG&E Corporation and the Utility recorded $325 million and $275 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.

For more information, see “Contributions to the Wildfire Fund Established Pursuant to AB 1054” in Note 2 and “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Loss Contingencies

As discussed below, PG&E Corporation and the Utility have recorded material accruals for various wildfire-related, enforcement and legal matters, and environmental remediation liabilities. PG&E Corporation and the Utility have also recorded insurance receivables for third-party claims.

Wildfire-Related Liabilities

PG&E Corporation and the Utility are subject to potential liabilities related to wildfires.  PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires.  See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Enforcement and Litigation Matters

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss contingency when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. Actual results may differ materially from these estimates and assumptions. See Note 14 and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims arising before August 1, 2023. PG&E Corporation and the Utility record a receivable for a recovery when they determine that it is probable that they will recover a recorded loss and they can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former MGP sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.

The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has a program related to certain former MGP sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.

When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, which could affect the cost of the remediation effort.

As of December 31, 2023 and 2022, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each. The Utility’s undiscounted future costs could increase to as much as $2.4 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.

Regulatory Accounting

As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. The Utility continues to apply ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and Regulated Operations” in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2023, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $23.1 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $22.3 billion.

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Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or court appeals. For some of the Utility’s regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition.

A portion of the Utility’s regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account, and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA and RUBA accounts track costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 pandemic. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC.

Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2023, the SB 901 regulatory asset was approximately $5.2 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered.  The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.

Asset Retirement Obligations

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8.

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation.

At December 31, 2023, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.5 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.

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Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. Adjustments to the pension and other benefit obligation are based on the differences between actuarial assumptions and actual plan results. These amounts are deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP, and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery through rates. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate, and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.

In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2024 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 and beyond.

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the Utility’s defined benefit pension plan, the assumed return of 6.0% compares to a ten-year actual return of 5.3%.

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 858 Aa-grade non-callable bonds at December 31, 2023. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:

The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:

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NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.